This invention relates to generation of electric power in stationary power plants.
Combined cycle systems are comprised of
1) One or more gas turbines each driving an electric power generator;
2) A steam turbine train comprised of two or more steam driven turbines piped for series steam flow and turning a common drive shaft that drives an electric power generator, and
3) A heat recovery unit in which heat in the combined gas turbine combustion exhaust gas stream is transferred to the steam turbine working fluid.
The gas turbines are fired with a fossil fuel gas, usually natural gas. Synthetic natural gas and low BTU gas are also suitable fuels for the gas turbines.
Currently, combined cycle units are designed so that the power generated by the gas turbines is about twice the power generated by the steam turbine train.
Combined cycle units usually have capability to fire fuel gas in the heat recovery unit. This feature is termed supplemental firing. Firing fuel gas in the heat recovery unit provides additional heat that is used to increase water working fluid circulation rate to increase power output from the steam turbine train. Fuel gas is injected directly into the gas turbine combustion exhaust gas stream in the heat recovery unit, usually close to the gas turbine exhaust gas inlet to the heat recovery unit. The gas turbine exhaust gas streams contain sufficient residual unburned oxygen to support combustion of the fuel gas.
The efficiency of fuel gas fired supplementally to generate incremental power is less than the efficiency of fuel gas fired in the gas turbines to generate base load power. Accordingly, supplemental firing is practiced usually during periods of peak power demand, when power prices are high.
Supplemental firing in the heat recovery unit is also practiced when the heat available in the turbine gas stream is not adequate to provide all the heat required to raise the temperature of the water working fluid stream to the specified steam turbine train inlet temperature. The combustion air feed rate to a gas turbine required for it to operate properly varies with ambient air conditions and, accordingly, so does the sensible heat in the combustion gas exhaust streams that is available for transfer to the water working fluid in the heat recovery unit.
Combined cycles have displaced traditional power units comprised of a steam boiler feeding a steam turbine-generator unit for base load power generation. This has occurred because technical improvements to gas turbines have significantly increased their generation capacity and fuel efficiency and reduced their investment and operating costs.
The pressure of steam generated in the heat recovery unit and fed to the inlet to the steam turbine train in current combined cycle units is typically in the range of 1000 psia to 1500 psia, which is well below the critical pressure of water, 3206.2 psia. However, in the process of the present invention the pressure of the water working fluid stream produced in the heat recovery unit and fed to the inlet of the steam turbine train is above the critical pressure of water. The water working fluid going to the steam turbine train is also above the critical temperature of water, 705.4 F. Accordingly the combined cycles of the present invention are termed Super Critical Combined Cycles.
Super critical combined cycles of the present invention have several advantages over conventional sub critical combined cycles. These advantages include simpler heat recovery units, capability to generate more incremental power by firing fuel gas in the heat recovery unit efficiently, capability to vary power output quickly to accommodate to changing power demand, higher fuel efficiency, and reduced air pollutant emissions.
The power output of the steam turbine train in super critical combined cycles of the present invention can be increased by a factor of up to 10xc3x97 by supplemental firing. Increasing power output by increments of this magnitude is not cost effective with sub critical combined cycles. Of course, the water working fluid circulation system, steam turbines, and generator must be designed to meet the peak rate operating duty experienced when supplementally firing fuel gas at maximum rate. This extra steam train capacity over the base load capacity is idle when supplemental firing is not employed, and therefore adds to the cost of the incremental power produced by supplementary firing. The efficiency of steam turbines does not vary significantly over the one to ten power output range.
Currently it is common practice to fire all of the supplementary fuel near the inlet to the heat recovery unit. This raises the gas temperature near the gas inlet to very high values, up to 2000 F. High gas temperatures induce formation of atmospheric pollutants and accelerate corrosion of heat exchanger tubes in the heat recovery unit. Embodiments of the present inject the supplementary fuel gas into the heat recovery unit at multiple selected points to reduce temperature peaks.
The fuel requirements of super critical combined cycles are generally marginally higher than for sub critical combined cycles because working fluid pressure and temperatures to the steam turbine train are higher. But the more significant efficiency advantage of super critical combined cycles arise because super critical combined cycles are amenable to and benefit more from certain fuel saving design options that are not practical with sub critical combined cycles. These design options reheat of steam side streams extracted from the steam turbine train and preheat of recycled condensate by steam side streams extracted from the steam turbine train,
The power output of super critical combined cycles of the present invention can be varied up and down much more quickly (with less time lag) to respond to changing power demand requirements than can conventional sub critical combined cycles. Operators value this flexibility of super critical combined cycles to adapt to changing power demand.
The flexibility advantage of super critical combined cycles derives ultimately from the physics of super critical fluids. When water that is below its critical pressure is heated to form steam it exhibits all the usual physical phenomena associated with boiling phase change. Condensate temperature rises to the saturation temperature, the condensate boils at constant temperature to form saturated steam consuming latent heat of vaporization, and then the saturated steam is superheated. When water that is above its critical pressure is heated it behaves differently from sub critical pressure water. The temperature of water above its critical pressure increases steadily and smoothly with no discontinuities due to phase change from condensate inlet temperature which is typically between about 100 F to 200 F to the turbine train inlet temperature which is typically about 1000 F. About 40% of the heat transferred to the super critical water working fluid is absorbed as the condensate stream is heated from 100 F to 600 F (0.080% per degree F.). About 45% of the heat transferred is absorbed between 600 F and 800 F (0.225% per degree F.). And about 15% of the heat is absorbed between 800 F and 1000 F (0.075% per degree F.). The enthalpy-temperature curve of super critical water exhibits an inflection point near its critical state point.
Accordingly, super critical combined cycle unit do not require a steam heads drum to separate saturated steam from boiling water whereas sub critical combined cycles do require a large steam heads drum. The steam heads drum contains a large quantity of liquid water hold up. This water hold up induces long temperature response time lags when boiler feed water circulation rate is changed to raise or lower the power output of the steam turbine train in sub critical combined cycles.
The overall fuel efficiency of a fossil fuel fired power unit or station is expressed as a heat rate: BTU""s (British Thermal Units) released by total combustion of the fuel divided by the net kilowatt-hours of power produced using that released heat, BTU""s/KWH. There are two ways to express the heat content of a fuel when computing heat rate: the lower heating value and higher heating value. The lower heating value (LHV) of the fuel is measured with the water in the combustion product stream formed by oxidation of hydrogen in the fuel not condensing and not giving up its heat of vaporization. The higher heating value (HHV) is measured with the water vapor condensing and giving up its heat of vaporization. Heat rates herein are computed using the lower heating value of fuel. Operators strive to minimize heat rate for the unit or station to reduce fuel costs and atmospheric pollutants emitted to the atmosphere.
The present invention comprises combined cycles wherein the pressure and temperature of the water working fluid for the steam turbine train exiting the heat recovery unit is above the critical pressure of water, which is 3206.2 psia and the critical temperature of water which is 705.4 F.
In one preferred embodiment of the super critical combined cycles of the present invention steam side streams are extracted from the steam turbine train, reheated in the heat recovery unit with sensible heat transferred from the gas turbine exhaust gas, and fed back into the steam turbine train.
In another preferred embodiment of the super critical combined cycles of the present invention a fuel gas is fired in the heat recovery unit to supplement the sensible heat in the turbine gas stream to heat working fluid for the steam turbine train. The supplemental heat released is used to increase the working fluid flow rate to the steam turbine, which increases the power output of the steam turbine train generator.
In some embodiments fuel gas is injected into the gas turbine exhaust gas stream several points in the gas stream as it flows through the heat recovery unit. One of the points is usually near the gas inlet to the heat recovery unit.
In another embodiment of the super critical combined cycles of the present invention part of the condensate stream is bypassed around the economizer tubes in the heat recovery unit and is heated in heat exchangers external to the heat recovery unit. The heat sources are steam side streams extracted from the turbine train. The diverted and preheated condensate stream is fed into the primary heating tubes in the heat recovery unit where it joins the main condensate stream that has been heated in the economizer tubes.